Various fracture-stimulation techniques are designed and employed in the petroleum industry for the common end result of placing sand proppant in hydraulically induced fractures to enhance oil or gas flow through a reservoir to the wellbore. Hydraulic fracturing of petroleum reservoirs typically improves fluid flow to the wellbore, thus increasing production rates and ultimate recoverable reserves. A hydraulic fracture is created by injecting a fluid, such as a polymer gelled-water slurry with sand proppant, down the borehole and into the targeted reservoir interval at an injection rate and pressure sufficient to cause the reservoir rock within the selected depth interval to fracture in a vertical plane passing through the wellbore. A sand proppant is typically introduced into the fracturing fluid to prevent fracture closure after completion of the treatment and to optimize fracture conductivity.
Hydraulic fracturing treatment is a capital-intensive process. In addition to the significant cost of a fracturing treatment itself, substantial oil and gas revenues may be gained as a result of a technically successful stimulation job, or lost due to an unsuccessful treatment. The effectiveness of a sand-fracturing treatment depends on numerous critical design parameters, including reservoir rock properties, the vertical proximity of water-productive zones, and the presence or absence of strata that act as barriers. Unsuccessful fracturing treatments typically result from inefficient placement of sand proppant in the induced fracture with respect to the targeted reservoir interval, which sometimes results in excessive water production due to treating "out of zone."
The formation is composed of rock layers, or strata, which include the objective petroleum reservoir, which is often a sandstone interval. When a fracture propagates vertically out of the defined hydrocarbon reservoir boundaries into adjacent water-productive zones, the well may be ruined by excessive water flow into the wellbore, or added expenses and disposal problems may be caused by the need to safely dispose of the produced brine water. Also, if the fracture propagates into an adjacent non-productive formation, the sand proppant may be wasted in areas outside the objective, and the treatment may not be effective. Either situation results in dire economic consequences to the well operator. Although it is sometimes possible to save a well that has been fractured "out of zone," the remedy is extensive, risky, and costly.
Present petroleum technology cannot readily predict when a hydraulic fracturing treatment will result in treating out of zone. The problem may be caused by too little or poor-quality cement between the well casing and the rock formation, or it may simply be caused by the absence of harder, fracture-resistant rock layers in the formation, which can act as barriers to the excessive propagation of fractures. Thus, the problem of treating "out of zone" during the hydraulic-fracturing process occurs frequently in industry.
An economical and successful fracture stimulation requires maximum controlled placement of fracture proppant in the reservoir zone, while avoiding treating into water-producing strata. The increased production revenue from successful fracturing treatments amounts to many millions of dollars each year. A successful fracturing treatment is typically evidenced by increased reservoir production performance resulting from concentrated placement of sand proppant in the petroleum reservoir within the induced hydraulic fracture.
Conversely, inefficient fracturing treatments cost the petroleum industry many millions of dollars each year both in foregone revenue from non-production of valuable hydrocarbons and in lost capital expenses associated with well drilling and completion. Indeed, some wells can be ruined entirely from poor fracturing.
Present industry methods for determining whether a fracture treatment has been treated "out of zone" have relied on post-treatment measurements. In such systems, a fracturing treatment is performed, the treatment is stopped, the well is tested, and the data are analyzed. With most known detection systems, moreover, the wait for post-fracturing data can be considerable, even up to several days, which can delay the completion operations, resulting in higher personnel and operating costs.
Specific known techniques for evaluating fracture treatments include the use of seismic hydrophone arrays, ultrasonic televiewers in the fracture interval, temperature surveys, pressure measurement, and flow meters over the fractured interval. However, those systems cannot be used while fracturing fluid is being pumped, because the downhole treating environment is hostile, which can affect the measurements. Also, such systems produce only indirect measurements of fracture propagation, and so they do not provide a good quantitative measurement of fracture height. In addition, some of those methods require the use of adjacent wells or can only be used in wells that are completed as "open hole" wells, that is wells without casing.
One system that falls within that class of techniques but allows measurement during the pumping of fluid is described in U.S. Pat. No. 4,832,121 to Anderson, which discloses a technique for monitoring the temperature near the wellbore as a function of depth. However, such temperature-based systems suffer from the problem of slow feedback from temperature changes, which can result in the "out of zone" problem developing before it is fully detected by the sensors. Also, Anderson's temperature technique has difficulty distinguishing between variations in rock temperature-conductivity and variations in temperature caused by fluid flow. Thus, temperature-measuring systems cannot provide a quantitative, as opposed to a qualitative, measurement of fracture height.
In addition, the particular method taught by Anderson is difficult to use with wells having casing, which is the most common situation. Anderson discloses how to install his system outside (or as part of)the casing while the well is being cased, but the system cannot be similarly installed in pre-cased wells. Anderson says that the system can be used inside the casing or inside the tubing, but such a system would not give reliable temperature readings while the fracturing fluid--which is significantly cooler than the formation--is being pumped nearby. Thus, the Anderson temperature-based system is not well-suited or practical for monitoring of fracture propagation during the fracturing process in most wells.
Another set of known techniques include the injection of radioactive tracer isotopes into the fracturing fluids, fracture proppants, or both during the fluid-injection or sand-injection steps in the fracturing process, allowing quantitative determination of exact fracture height, by a process known as "gamma well logging." However, such systems can determine fracture growth only after a fracturing treatment is completed. Gamma-radiation measurement tools, such as Schlumberger's Multiple Isotope Tracer Tool (MTT) or Schlumberger's Natural Gamma Ray Tool (NGT), can then detect the tracers and collect data that can be analyzed to determine fracture height or the concentration of proppant. The tool is inserted after the fracturing treatment is completed and moved vertically through the formation interval, within the cased wellbore, to detect the placement of tracers in the formation.
However, none of the logging tools offered by Schlumberger or others in industry is capable of detecting the propagation of fractures during the injection of sand-laden fluid, that is, in "real time." In particular, the processed spectral data from logging methods is typically not available concurrent with the fracturing treatment because additional computer processing would be required to distinguish the gamma rays emitted by the tracer isotopes outside the casing from the gamma rays emitted by tracers in the fluid inside the casing. Most existing well-logging tools are not designed for use with the tubing strings that are generally used to pump fluids into the formation, and it is generally considered very risky to pump fluid directly into the well in the presence of a logging tool without using tubing.
Thus, there is presently no method or logging tool available to the petroleum industry for accurate, quantitative measurement of fracture height or proppant placement measurement during the fracturing process.
Existing post-process "logging" or measuring devices are inadequate because operators cannot feasibly stop and restart the fracturing job to take a measurement. Fracturing fluid is generally pumped into the formation at extremely high pressure, to force open the fractures, and an increasing proportion of sand is added to the fluid to prop open the resulting fractures. Stopping the pumping will relieve the pressure, and depending on the point at which it occurs, undesirable results may occur, such as the closing of the fractures, the reversal of fluid flow back into the wellbore, or the build-up of sand in the hole. Then, after the "logging" operation is completed, the pumping cannot be restarted at the point at which it was left off. Instead, the fracturing job would have to be redone from scratch, with unpredictable results, and it may even be impossible or impractical to redo the job at all.
As a consequence, current methods of fracturing are an art, not a science, in that skilled operators must make educated guesses at factors such as the length of the fracturing job and the rate of increase of sand concentration. Current measurement methods allow only a retrospective view of the fracturing job, in other words, only after any damage has already been done.
By contrast, real-time fracture growth monitoring would allow well operators to control fracture dimensions and to efficiently place higher concentrations of sand proppants in the desired reservoir interval. If the fractures came close to extending out of the desired zone, the operator could terminate the fracturing job, automatically or manually. In addition, real-time analysis of the ongoing treatment procedure would allow the operator to determine when to pump greater concentrations of sand proppant, depending on factors such as the vertical and lateral proximity of oil-water contacts with respect to the wellbore, the presence or absence of water-producing strata, and horizontal changes in the physical properties of the reservoir rock.
Thus, it is an object of this invention to provide systems and methods for quantitatively monitoring in real time the developing growth of hydraulic fractures during the hydraulic fracturing process.
It is another object of the invention to provide systems and methods permitting more accurate placement of sand and other proppants in the reservoir via fracturing fluids.
It is another object of the invention to provide systems and methods for allowing better control of the fracturing process.
It is another object of the invention to provide systems and methods for preventing the problem of fracturing "out of zone."
It is another object of the invention to provide systems and methods for improving the reliability of hydraulic fracturing methods.
It is another object of the invention to provide systems and methods for improved automation of the hydraulic fracturing process.